Depending on the project, a typical drilling project to begin fluid extraction from the Earth may go anywhere from 25 feet below the Earth's surface to well over 20,000 feet below the Earth's surface. Every drilling project is unique, and may require different parameters for use. Thus, for example, a short range depth hole may only require a small diameter hole to be dug, whereas a long range depth hole may require a much larger diameter hole to be dug. Thus, for example, a 7000 foot deep hole may typically require the creation of an approximately 18 inch diameter surface casing substantially throughout the length of the hole being dug. As the hole is being slowly dug, the drilling bit is removed from the hole, and surface casing is inserted into the diameter of the hole in order to create a reinforcement wall or barrier which also prevents any external material (such as gas or oil) from coming to the surface during the pressurized drilling process. Surface casing pipe is typically formed of a metal or metal compound and usually comes in 20 to 30 foot lengths which can be interconnectable to allow longer length casings (as may be needed for longer depth holes). The diameter of the hole being dug is generally larger than the surface casing inserted into the hole. Once the casing is installed, cement is then pumped down inside the casing and forced outside the bottom and circulated to the surface, thereby creating a permanent down hole bore. To help the cement cure, calcium chloride may be added to the cement. Calcium chloride in the cement also helps the cement to dry in adjacent water pockets underneath the Earth's surface. By cementing the casing to the Earth, a barrier is created which prevents any liquid, gas or other undesirably contaminants nearby from escaping to the Earth's surface during the drilling process.
When the drilling process is completed, and all conventional downhole stabilizing structures are in place downhole (e.g., cement casing, perforations stimulation and a tubing string), a rod pump may then be inserted into the tubing to begin the fluid (e.g., gas, oil, water, etc.) extraction from adjacent perforations P in the casing. As seen in FIG. 1, a typical downhole sucker rod pump RP (also known as a reciprocating pump) is connected to the surface pumping unit SP by a series of rods R, which are collectively commonly referred to as a “rod string”. Each rod is typically formed from high strength steel or steel alloy.
A sucker rod pump RP is used primarily to draw oil from underground adjacent fluid reservoirs by providing a reciprocal (up and down) motion, but can be adapted to extract other fluids as well. In operation, the surface pump SSP pulls the sucker rod upward and then allows the rod string to be moved downwardly by gravity. During the pumping process' upstroke cycle, formation pressure allows the adjacent reservoir's fluid F to pass through a valve in the downhole sucker pump and into the barrel of the pump. The fluid F will be held in place within the barrel. On the down stroke, the travelling valve unseats and fluid inside the pump barrel will be forced into the tubing column, and while the standing valve seats, fluid is prevented from flowing out of the barrel and back into the reservoir, permitting the adjacent reservoir fluid to enter the barrel, while preventing fluid from moving back down into the hole. This process repeats cyclically, with the fluid being slowly extracted into the tubing. The fluid will continue to pass upwardly in the tubing, where it will be extracted into a storage tank or like structure.
Subsurface pumps RP are also referred to as “sucker rod pumps” in the industry. A sucker rod pump (e.g., traveling barrel pump) is a relatively simple device, and can be operated over long periods of time with relatively little cost and maintenance. Sucker rod pumps are generally attached to a lower end of a sucker rod at the ground level, and then the entire apparatus is placed into the well as a complete unit. The sucker rod pump can then be placed in a fixed location at a depth in the tubing by a seating nipple N which was pre-fitted in the tubing at the required depth. There are typically two types of downhole sucker rod pumps found in the industry, an insert (or, rod) pump, and a tubing pump. The insert pump (also known as a traveling barrel rod pump or a stationary barrel rod pump) is installed on the sucker rod string, whereas the tubing pump is attached directly to the tubing and is run into the well as a complete unit.
A typical sucker rod must extend from the surface pumping unit all the way down to the sucker rod pump, which may be several thousand feet below the surface. Currently, a modern day top discharge cage (or, discharge valve) apparatus is used to connect the rod to a downhole pump (such as a sucker rod pump). These conventional cages, however, are designed to discharge the fluid coming from within the pump horizontally (or, laterally) towards the adjacent tubing surfaces during the pumping process, thereby significantly causing erosion to the tubing surface over time due to cyclic stress, eroding the thickness of the tubing until tubing failure occurs. Tubing failure represents a significant cost to the oil recovery industry, and the industry has attempted to use stop-gap methods to try to slow the erosion process (like for example, by applying ceramic material or powder coating to the tubing), however, these methods are modestly successful. Moreover, shutting down a well in order to replace the tubing and associated structures or parts is also expensive and time consuming, resulting in loss of potential income. Further, transportation is also a high cost to consider, as parts are moved to and from the well to fix the problem. And, when worn pipe or tubing must be replaced, the long delivery time and large expense of new parts can be a significant impediment to recovery operations. When a pumping well needs service, a workover rig is usually required, which is extremely costly.
Thus, there remains a need for a centralizing vertical flow cage which substantially reduces any erosion or abrasion of the surrounding tubing surface during the pumping process. It is therefore an exemplary feature of the present invention to provide a novel method, system or apparatus for a vertical flow cage which substantially maintains longitudinal alignment in the tubing while presenting minimal resistance to the axial flow of fluids during the pumping process.